In the drilling of well bores penetrating subterranean formations, drilling fluids are generally circulated through the well bores to remove cuttings therefrom and accomplish other purposes. Most drilling fluids are comprised of suspended particles of hydrated clay in water and weighting materials such as barite are frequently combined with the drilling fluids to increase the densities thereof. Various additives are also commonly utilized in drilling fluids to impart desired properties thereto, such as to bring about low fluid loss from the drilling fluids to subterranean formations in contact therewith. However, once a well bore penetrates a subterranean formation containing desired hydrocarbon fluids, insoluble materials in the drilling fluid such as clay and barite can be damaging to the formation. That is, a filter cake or sheath of such insoluble material can form on the face of the formation and some solids of the filter cake can penetrate into the formation which in turn can result in a permanent reduction in the permeability and hydrocarbon producing ability of the formation.
In order to help prevent damage to producing formations during the drilling and completion of well bores penetrating such formations and during subsequently carried out workover procedures, brines have heretofore been utilized in lieu of drilling fluids containing insoluble solids. The brines are non-damaging because the salts contained therein which provide density to the brines are dissolved, and no solids are placed in contact with the formation thereby. Because such drilling, completion, and workover brines do not contain undissolved solids, they are commonly referred to as "clear brines."
In operations carried out in well bores penetrating subterranean formations containing fluids under high pressures, the brines utilized must have very high densities, e.g., densities in the rage of from about 9.0 to 21.5 pounds per gallon, in order to prevent the pressurized fluids from blowing out of the wellbore. These brines typically contain KCl, NaCl, CaCl.sub.2, NaBr, CaBr.sub.2, ZnCl.sub.2, ZnBr.sub.2, sodium formate and potassium formate, or combinations of such salts, and are of relatively high cost.
Because of the high cost of high density drilling, completion and workover brines, they are usually recovered, filtered, and reused in well servicing operations. The loss of such brines is expensive and certain brines are not compatible with certain formation brines causing damaging precipitation therein, and as a result, fluid loss reduction procedures and additives have heretofore been utilized with high density brines. These include increasing the viscosity of the brines by combining hydratable viscosifiers therewith such as hydroxyethylcellulose and derivatized polysaccharides. While combining such viscosifiers with high density brines has resulted in the reduction of fluid loss, the disadvantages are that relatively large quantities of the viscosifiers are required, difficulties are often encountered in dissolving and hydrating the viscosifiers in high density brines, especially brines containing zinc bromides; and the viscosity produced is often lost or greatly lessened when the brines are used in relatively high temperature or low pH environments.
U.S. Pat. Nos. 4,175,042 and 4,822,500, incorporated herein by reference for all purposes, disclose drilling, workover and completion fluids comprising a saturated brine solution in which a water soluble salt, which is not soluble in the saturated brine, of a particular size range is suspended in the saturated brine along with suitable polymeric viscosity and suspension additives and suitable fluid loss control agents. Representative saturated brines may contain one or more salts such as KCl, NaCl, CaCl.sub.2, ZnCl.sub.2, KBr, NaBr, CaBr.sub.2, ZnBr.sub.2, Na.sub.2 CO.sub.3, K.sub.2 CO.sub.3, and NaHCO.sub.3. Representative water soluble, particulate sized salts are KCl, NaCl, CaCl.sub.2, CaBr.sub.2, Na.sub.2 SO.sub.4, Na.sub.2 CO.sub.3, K.sub.2 CO.sub.3, and NaHCO.sub.3. Representative viscosity and suspension additives are xanthan gum, cellulose ethers, and guar gum derivatives. Representative fluid loss control additives are: calcium, chrome, or ferrochrome lignosulfonates; carboxymethylcellulose; and starches such as corn, potato, and tapioca, and their derivatives. U.S. Pat. No. 4,822,500 discloses that xanthan gum and a particular epichlorohydrin crosslinked hydroxypropyl starch synergistically combine in the saturated brine to provide excellent suspension and fluid loss control. Such fluids having a saturated sodium chloride base brine have been eminently successful, and are a preferred fluid for drilling in hydrocarbon bearing formations, such as in "horizontal drilling."
The use of derivatized starch ethers in combination with bridging solids and viscosity/suspension additives, although effective in these brine fluids to reduce the fluid loss, requires a concentration that provides excessive viscosity upon exposure to higher temperatures.